deliverable 3.1 initial assessment of risks and barriers ... · 3.3 tariff reforms ... this table...

MIRREIA

Mitigating Risk and Strengthening Capacity for Rural Electricity Investment in Africa

Deliverable 3.1

INITIAL ASSESSMENT OF RISKS AND BARRIERS TO INVESTMENT AND FINANCE IN

RENEWABLE ENERGY IN KENYA, TANZANIA AND UGANDA

December 2005

MIRREIA - Initial Assessment of Risks and Barriers to Investment and Finance in Renewable Energy in Kenya, Tanzania and Uganda

December 2005 2

Table of Contents

KENYA............................................................................................................................... 4 1. Summary of Recent Projects and Attempts in Kenya............................................. 4 2. Case Studies ............................................................................................................ 5

Case Study 1: Kinangop Wind .................................................................................... 5 Case Study 2: Marsabit Wind ..................................................................................... 6 Case Study 3: Greenpower ......................................................................................... 7 Case Study 4: Mpeketoni Wind ................................................................................... 8 Case Study 5: Mumias Sugar Company...................................................................... 8

3. Policy/Regulatory Risks.......................................................................................... 9 3.1 Overview of Agencies...................................................................................... 9 3.2 Process for Securing Permits and Approvals ............................................... 10

4. Significant Policy/Regulatory Issues .................................................................... 11 4.1 Liberalization of Energy Sector .................................................................... 11 4.2 Utility/Government Interest in Power Purchase Agreements (PPAs) .......... 13 4.3 Tariffs ............................................................................................................ 13 4.4 Interconnection of Regional Grids................................................................ 14

5. Financial Risks...................................................................................................... 15 5.1 Assessment of Finance Risks......................................................................... 15

6. Overview of Finance Institutions and Agencies ................................................... 16 6.1 Summary ....................................................................................................... 16 6.2 Commercial Banks ........................................................................................ 16 6.3 Savings and Credit Associations (SACCOs)................................................. 16 6.4 Microfinance Institutions .............................................................................. 17 6.5 Development Bank ........................................................................................ 17

7. Technical Risks..................................................................................................... 17 TANZANIA...................................................................................................................... 18

1. Recent Projects and Attempts in Tanzania ........................................................... 18 2. Highlights of Risks that Investors Face: Mini Case Studies................................ 19

Case Study 1: Mafia Island ....................................................................................... 19 Case Study 2: Mufindi Mini-Hydropower................................................................. 20 Case Study 3: Njombe Mini-Hydropower................................................................. 22

3. Policy and Regulatory Risks................................................................................. 23 3.1 Restructuring and Unbundling of TANESCO ............................................... 24 3.2 Rural Energy Agency (REA) and Rural Energy Fund (REF) ....................... 24 3.3 Tariff Reforms ............................................................................................... 25 3.4 Investors Guide in the Energy Sector ........................................................... 27

4. Financial Risks...................................................................................................... 28 5. Technical Risks..................................................................................................... 31 6. Other Factors......................................................................................................... 32

UGANDA ......................................................................................................................... 34

1. Recent Projects and Attempts in Uganda.............................................................. 34 2. Highlights of Risks that Investors Face: Mini Case Studies................................ 35


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Case Study 1: WENRECO ........................................................................................ 35 Case Study 2: Kakira Sugar Works ......................................................................... 36 Case Study 3: Hydromax ......................................................................................... 37

3. Policy and Regulatory Risks................................................................................. 37 3.1 Summary of Political and Regulatory Risks ................................................. 40 3.2 Tariff Reforms ............................................................................................... 40 3.3 Investors Guide in the Energy Sector ........................................................... 41

4. Financial Risks...................................................................................................... 42 5. Technical risks ...................................................................................................... 43 6. Other Factors......................................................................................................... 46


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KENYA

1. Summary of Recent Projects and Attempts in Kenya At present, there are three Independent Power Producers (IPPs) in Kenya that generate and sell electricity in bulk to the Kenya Power and Lighting Company (KPLC), which is the country’s only public electricity supplier. The three IPPs are as follows: Iberafrica Power Ltd (56.5MW), Tsavo Power Company (74.2MW), and OrPower (13MW). In 1997, in response to a severe shortage of power, three IPPs were negotiated as 7-year power purchase agreements (PPAs). All three of the original IPPs have signed follow-on contracts. In 2001, Tsavo Power Company signed a 20-year PPA, and, in 2004, Iberafrica Power signed a 15-year PPA. OrPower, which has been generating power using geothermal resources at Olkaria near Naivasha, has signed a 20-year PPA and will be increasing its capacity to 48MW by 2008. (The Oserian Development Company, a horticultural enterprise, has an agreement with KenGen allowing it to use a low output geothermal exploration well in the nearby Olkaria field to supply heat to a greenhouse complex.1) Conservative forecasts for Kenya suggests that, with unconstrained usage, demand will grow by 4-5% each year for the next five-six years. In response to this need for power, KenGen and KPLC have announced the following committed additions to the national grid2: Project MW Estimated

Commissioning Date

KenGen New Gas Turbine 70 August 2006 Eburru Geothermal 2.5 November 2006 Sondu-Miriu Hydro 60 July 2007 Kiambere rehabilitation Hydro

20 July 2007

Kindaruma 3rd Unit Hydro 20 July 2007 Redevelopment of Tana 10 July 2007

1 This is a small project with no real impact on the national grid. Details can be found in Greenhouse Gas Heating at Oserian Farm, Lake Naivasha, Kenya, a project summary by Bruce Knight, Hagen Hole, et al. that can be found at http://www.unep.org/gef/content/geothermal_title.htm 2 Table adapted from one included in a presentation delivered by Eng. David Mwangi, Chief Manager of the Planning, Research, and Performance Monitoring division of KPLC, at a meeting on the Embakasi project bid meeting on 15 September 2005 in Nairobi.


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Hydro Kipevu Combined Cycle 60 July 2007 Embakasi I IPP MSD 80 September 2007 Olkaria II 3rd unit Geothermal

35 April 2008

Orpower 4 Geothermal 35 April 2008 TOTAL 392.5 With the exception of the geothermal projects (Eburru, Orpower, and the expansion of Olkaria II), this table suggests that non-hydro renewables are not likely to play a major role in Kenya’s electricity future. Kenya is the only country in East Africa to have tapped the potential of the region’s geothermal resources (which currently provide 10% of the country power), and there is tremendous scope for further exploration and development of this and other renewable resources. With the exception of geothermal resources (which are expected to contribute 210 MW by 2026), no mention is made of non-hydro renewables in the country’s Least Cost Development Plan. While not included in KPLC forecasts at present, it is believed that two renewable energy electricity projects will be moving forward in the near future. One is Kinangop, a 30MW wind power project that is a joint venture between a private developer and KenGen. Mumias Sugar Company (MSC) has publicly announced that it is developing a bagasse cogeneration project and will seek a PPA that would allow it to export 10-20MW of power to the grid. At present, MSC does not yet have an agreement with KenGen.

2. Case Studies Following are brief descriptions of projects that are in development or are moving forward. Each description identifies the various risks that investors in renewable rural electricity projects face. Strategies that project developers have used to mitigate key risks are identified.

Case Study 1: Kinangop Wind

It is expected that a 30 MW wind power project in Kinangop, in the Nyandarua District of Kenya, will be completed in 2007. The project is a joint venture between EcoGen, a private company, and KenGen, the Kenyan power generation company, and is an example of a successful public-private partnership.

According to Sacha Cook of EcoGen, the final joint venture agreement with KenGen and financial close are expected by the close of 2005. The


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project, which was first announced in August 2005, will cost an estimated KSh 3.7 billion and is being financed in part by DANIDA.

This project has benefited from DANIDA support and from an excellent location with good proximity to transmission lines. EcoGen’s ability to develop a PPP with KenGen has helped this project move forward. The project has also secured funding for its carbon offsets.

Case Study 2: Marsabit Wind

WindFlow Power Limited, a private project developer, is trying to develop a 90MW wind project in Bubisa, which is in Marsabit District in Northern Kenya. This is a sparsely populated area of Kenya with significant potential for wind power generation. WindFlow’s initial anemometry data suggest that consistent wind speeds of at least 10 m/second can be expected. The proposed project site will occupy 2,500 acres, which the company proposes to lease in a 60-year lease from the Marsabit County Council. WindFlow estimates the total project cost to be $160 million.3

If WindFlow is successful in developing a PPA for this 90MW project, it hopes to expand capacity and add another 90MW in the same area within a decade. As with EcoGen, WindFlow hopes to develop a PPP with KenGen and has proposed a structure where KenGen would hold 30% of the shares while WindFlow held 70%. WindoFlow’s director told ESDA that he has informally been assured that he will be able to negotiate a PPA for generation only; KPLC would take responsibility for transmission. At present, due in part to WindFlow’s influential backers, the company has secured a letter of support from KenGen, which has set the stage for PPA negotiations.

While many project developers have tried in the past to develop wind projects in Northern Kenya, such efforts have failed because of lack of transmission lines connecting the area to the national grid. WindFlow’s success to date in moving this project forward may lie in their ability to address this risk by finding an innovative financing mechanism for the construction of transmission lines.

In the project brief, WindFlow describes its plan for transmitting the power generated to the national grid as follows:

The power produced by the Wind-Farm will be delivered to the Kenya National grid via a newly constructed 220KV overhead line, connecting the

3 Using the standard assumption that each MW will cost $2 million, WindFlow’s estimate seems a bit low.


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Wind-Farm Marsabit along the existing National Truck road up to Nanyuki. The line will run from Bubisa to Marsabit (40Km) Marsabit to Archer-Post (277Km) then to Isiolo (33Km) to Nanyuki 82Km a total of about 440Km.

According to WindFlow, the Export and Import Bank of India has agreed to loan money at favorable terms to KPLC to build the 440 km of transmission lines to plug the wind power generated into the national grid. This transmission project will be separate from the power generation agreement and will be financed separately.

This arrangement, if it comes through, would help WindFlow mitigate one of the biggest risks of project development in a remote area, namely the lack of transmission lines and hence lack of options to connect to national grid.

Case Study 3: Greenpower

Greenpower is a small firm that is trying to develop micro- and pico-hydro sites around the Mt. Kenya area. There are many prosperous communities in this area, where people cultivate tea, coffee, and other cash crops. Greenpower has identified 52 potential project sites, ranging in size from 100W to 1.5kW. Of these 52 sites, Greenpower is moving forward to develop 3 projects using its own locally designed and manufactured turbines. Greenpower pre-invests in the hardware and asks customers to pay a standing charge per household, as well as a usage fee per kWh consumed. Greenpower estimates that its electricity, including distribution, costs customers an average of $2500/kW.

One of the key risks with this kind of project is the time and effort required to collect monthly payments from customers. Greenpower mitigates this risk by asking community groups to organize payment themselves; agreements to do so are put in place before the hardware is installed. The community groups also agree to maintain the installations, once Greenpower and its engineers have installed the system and set up a mini-grid distribution network in the community.

Greenpower’s experiences so far have been mixed. The first installation, which was already serving 30 households with plans for expansion, had to be removed (at tremendous cost to Greenpower) because of failure of the community to organize payment. In addition, Greenpower told ESDA that local and national government officials have created complications by demanding connections in communities that do not seem to have the infrastructure in place to take responsibility for system maintenance and bill collection.


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Greenpower has found that, in rural off-grid areas with significant economic activity, there is a higher willingness to pay than in rural areas that suffer from a lack of livelihood options. Greenpower has decided not to pursue grid-connected projects (even though a 1.25MW project site has been identified) because the prices offered by KenGen would be much lower than what can be earned directly from customers being served by mini-grids. The transaction costs of developing grid-connected projects are also, Greenpower has determined, too high, given the modest amount of power that could be generated.

Case Study 4: Mpeketoni Wind

Mpeketoni Electricity Project (MEP) is a community-based electricity company in Lamu District on the Kenyan coast. MEP has been operational for 10 years and is currently serving 240 customers using a mini-grid. Scottish Power/E7 Fund is working with MEP to investigate the viability of combining wind with diesel to improve MEP’s environmental profile while enabling it to serve additional customers. At present, initial anemometry data is being analyzed and distribution possibilities are being assessed. The wind speeds are lower than 7 m/s, which is not ideal. However, the community development benefits of the project are so high that Scottish Power and the E7 Fund have decided to move forward.

This project has received the support of the Ministry of Energy due to existing ties between the Ministry, MEP, and Mpeketoni community leaders. This project suggests the importance of being able to tap existing channels of communication in developing new projects; without MEP’s links to the Ministry, it may have been challenging to move this project forward.

Gaining access to the Ministry of Energy and other influential agencies is difficult in Kenya – this is a critical policy risk. Project developers with existing ties have an advantage, even if there are project sites or technology choices are not ideal.

Case Study 5: Mumias Sugar Company

Mumias Sugar Company (MSC) is one of the few profitable sugar companies in Kenya. MSC, along with the rest of the sugar sector, is facing a more competitive market once national policies to protect domestic sugar from competition are phased out. MSC engaged ESDA to identify options to enable it to remain competitive in on open market. At present, MSC produces only 1-2MW of power, which it exports to the grid on a low-paying spill contract.


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In April 2005, ESDA completed an assessment and advised MSC that, to remain competitive, it should diversify its product base and invest in power generation. ESDA analysis indicated that MSC could produce and export 20MW of power to the national grid; ESDA also suggested that MSC might be able to wheel power to PanAfrican Paper Mills, the country’s largest single user of power, which is located nearby. ESDA also recommended that MSC maximize its power output in order to get the best possible terms from KenGen and a favorable evaluation from the country’s regulator, the ERB.

MSC has decided to produce only 10MW of power and to produce ethanol. While MSC is following the diversification strategy laid out by ESDA, the decision to produce only 10MW of power will likely result in low prices being offered by KenGen. The decision to publicly announce their intentions before negotiating a final deal with KenGen may also lead to lower prices being offered to MSC.

This case suggests how private players’ poor understanding of the regulatory framework (and how best to negotiate within it) can adversely affect projects in development.

3. Policy/Regulatory Risks

3.1 Overview of Agencies In discussing the policy and regulatory risks investors in Kenya’s rural electricity sector face, it is useful to understand the major agencies and their roles: AGENCY MAJOR

RESPONSIBILITY SIGNIFICANT ISSUES PERTAINING TO AGENCY

Ministry of Energy

Sets energy policy for the country. Lead agency for rural electrification.

Kenya Electricity Generating Company (KenGen)

Electricity generator, currently generates 80% of the country power

Facing privatization of 30% of government-held shares in 2006. Under the World Bank’s Energy Sector Recovery Program (ESRP), efforts are underway to improve the utility’s performance.

Kenya Power and Lighting

Purchase bulk power from generating

The Government of Kenya owns 51% of KPLC, and the rest of the company


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Company (KPLC)

companies and transmits and distributes electricity. Responsible for retailing electricity to customers. The only licensed Public Electricity Supplier (PES) in Kenya.

is publicly traded. KPLC has been operating on performance-based contracts since 2004-5. The Government of Kenya, in response to concerns raised by major donors, has agreed to use the services of a Management Services Contractor (MSC) in order to improve performance and enhance customer service. The MSC will set up separate business units within KPLC for its eventual full privatization. The MSC is expected to begin work in January 2006.

Electricity Regulatory Board (ERB)

Regulate the electric power sector. Protect consumer interests and guarantee the economic and financial viability of sub-sector utilities. Review and adjust tariffs for everyone who transmits and distributes electricity for sale.

Under the World Bank’s ESRP, ERB has contracted consultants to address tariff reform and other issues.

National Environmental Management Authority (NEMA)

Government parastatal responsible for all matters relating to the environment, including environmental reviews of proposed projects and the issuance of environmental permits.

NEMA is Kenya’s Designated National Authority (DNA) and so its approval must be given for any application for CDM support.

3.2 Process for Securing Permits and Approvals


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A renewable energy project developer must take the following steps to secure approval and permits for a proposed project:

1. Secure the land through a lease or easement agreement with the landowner.

2. Submit a copy of the proposed site map with an application for license to the Electricity Regulatory Board (ERB)

3. Obtain a license/appropriate licenses from ERB 4. Reach a power purchase agreement with the only national body

responsible for electricity transmission and distribution, the Kenya Power and Lighting Company (KPLC). Currently there are no special tariffs for power produced from renewable energy. A bulk/minimum tariff is determined by ERB and KPLC charged.

5. Carry out an environmental impact assessment needs to, the responsible body is the National Environmental Management Agency (NEMA)

6. Obtain permits from the local authorities.4

4. Significant Policy/Regulatory Issues

4.1 Liberalization of Energy Sector The liberalization of Kenya’s energy sector began in October 1996, in response to reductions in donor support for the power sector. The Electric Power Act of 1997 was a key output of the liberalization process. It supported the unbundling of generation from transmission, distribution, and retailing capacities. It also established open competition as government policy; all generation facilities were to be competitively bid in a process open to both the public entity (KenGen) and private firms. From this point on, the state utility was divided between KenGen (responsibility for power generation) and KPLC (responsible for transmission and distribution). There is some discussion that, by the end of 2006, a national transmission company (notionally called Transco) will be established, leaving KPLC (and possibly another entity, to be created) with distribution functions only.5 However, it is not clear that this will be carried forward, as the World Bank has suggested that KPLC might be “privatized as an integrated entity carrying out system

4 Developing a Wind Energy Regulatory Framework for Kenya. Energy for Sustainable Development Africa. 2005. 5 The Kenyan IPP Experience, Working Paper 49. Anton Eberhard and Katharine Gatwick. August 2005. Management Programme in Infrastructure Reform and Regulation, University of Cape Town.


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operation, transmission, distribution, retailing, and wholesale power purchasing.”6 The continuing uncertainty about the future of the electricity sector creates regulatory risk for project developers, who cannot be sure who they will be dealing with when a project comes to fruition. The reforms of 1996 allowed IPPs to enter the energy sector and, in 1997, three IPPs were licensed. However, no regulator was in place to approve the first IPPs. The 1997 Electric Power Act established the ERB, which began its operations one year later. The State Corporation Act, passed after the Electric Power Act, places ERB under the Ministry of Energy and influences the work of the ERB. The ERB does not directly manage the issuing and revocation of licenses; rather, it guides the Ministry on what needs to be done. This structure has raised some concerns about ERB’s ability to act as a truly impartial and independent regulator.7 Because of when it was established, the ERB was not involved in the first set of PPAs negotiated in Kenya.8 In 1999, a severe drought forced Kenya, with its reliance on hydropower, to seek other sources of power. The Ministry of Energy negotiated to have three emergency diesel-fired power plants (using only short-term contracts) added to the national grid. These were, because of the power crisis, not negotiated as carefully as the 1997 IPPs had been, and the costs to KPLC and the consumer were high. In their paper on the Kenyan IPP experience, Anton Eberhard and Katharine Gatwick describe how the response to the drought affected the public perception of private sector involvement in the power sector and of IPPs:

With IPPs associated with higher cost power, the drought led to public outcry against private sector participation, which was seen to be taking advantage of a poor country in a dire situation. Allegations of corruption in the power sector, together with a call to reduce tariffs, gained momentum. The new government, which came to power in December 2002, on the heels of the drought and a drought-induced recession, pledged specifically to address ESI reform and reduce tariffs.9

The new government investigated alleged corruption in the generation of power and, ultimately, individuals from Iberafrica and KPLC were indicted for corruption. The impact of these indictments on the political support for new IPPs is unclear,

6 Restructuring and Privatization of the Power Sector in Kenya. PPIAF Activity Overview, the World Bank. October 2004. 7 African Power Sector Reforms: Some Emerging Lessons. Njeri Wamukonya. March 2003. Energy for Sustainable Development, Volume II No. 1 8 Eberhard and Gatwick, op. cit. 9 Eberhard and Gatwick, op. cit.


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and the Ministry and KenGen have maintained that they will negotiate PPAs as appropriate to meet the country’s power needs. Following the 1996-1997 reforms, the industry can be characterized as a single buyer model, with KPLC responsible for all transmission and distribution. Because KPLC has a monopoly on network functions, ERB’s calculations on tariffs weigh KPLC’s revenue requirements heavily, in addition of course to determining a reasonable rate of return on the capital invested to provide services. ERB is working with KPLC to reduce transmission and other system losses to no more than 15%, which will reduce overall costs to the consumer for electric power. 10 KenGen, which produces 80% of the country’s power and is currently government-owned, will be privatized in 2007. The Government of Kenya will sell 30% of its stake in the generator through an Initial Public Offering (IPO). A consortium lead by Dyer & Blair Investment Bank has won the tender to provide brokerage services for the IPO. A Privatization Steering Committee that was established earlier this year is overseeing this process.

4.2 Utility/Government Interest in Power Purchase Agreements (PPAs)

KenGen and KPLC have expressed interest in developing new PPAs to meet energy requirements. The PPAs that KPLC has in place with IPPs are long-term, bilateral take or pay contracts. Each agreement has a bulk tariff structure that includes capacity charge, energy charge, fuel pass through, and a clause to increase prices based on indexed rates of inflation. At present, the ERB is considering how to handle ancillary services, such as reactive power and voltage support, which are not addressed in existing PPAs. The wheeling of power is allowed only to customers who use a minimum of 25MW; this allows wheeling of power to one customer. The ERB has indicated that the wheeling of power to smaller users may be allowed in the future. This may create new project opportunities.

4.3 Tariffs There are at present 16 customer categories for the purpose of tariffs and limits on energy that may be consumed. The lowest block for tariffs is the Life-Line Tariff (LLT), and customers in this block are restricted to 550 kWh/month. The subsidy provided to this block has been targeted for reform, as it is provided to all 10 Retail Electricity Tariffs Review Policy: 2005. Electricity Regulatory Board, April 2005


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domestic customers, not just those who are most in need of economic assistance. Raising the tariff for household customers not in need of economic assistance (that is, those households which use more than 50kWh of electricity a month) would allow for cross-subsidies to be used and might, if tariffs were set to allow cost recovery of electricity generation, encourage new investors to develop power projects. The ERB has indicated that it will be revising customer categories and capping the low-cost household tariff to those households that use 50kWh or less a month. In addition, ERB will be introducing optional Time-of-Use tariffs for commercial/industrial customers to encourage the use of off-peak electricity. In April 2005, KenGen agreed to provide a subsidy in the form of lower prices (from the previous wholesale rate of KSh 2.36/kW (US$.31) to KSh 1.76/kW (US$.23). This subsidy ended in November 2005, which will likely cause retail power prices to increase. The impact of these prices increases, and of future subsidies given the impending privatization of KenGen, is unclear. This uncertainty creates policy risks for project developers.

4.4 Interconnection of Regional Grids The possibility of the development of a regional electricity grid in East Africa, as well as the development of regional interconnections, creates opportunities and hurdles for rural energy project developers. At present, these regional initiatives are being discussed11:

• East African Power Master Plan. In May 2005, an initial regional least cost power plan linking Kenya, Uganda, and Tanzania was developed.

• Kenya-Tanzania Interconnection. Dutch funding is expected to become available to support link sources of power in Kenya and Tanzania to each other.

• Tanzania-Zambia Interconnection. This interconnection is being funded by the private sector and may be developed as soon as 2009. Kenya would also benefit if the Kenya-Tanzania interconnection comes to fruition.

• Nile Basin Initiative. Involving the ten countries in the Nile catchment area, this project is examining options for both interconnection and for the development of a regional power pool. At present, four interconnection projects (Kenya-Uganda, Uganda-Rwanda, Rwanda-Burundi, and Rwanda-DRC) are being discussed and the development of specific plans may be supported by the African Development Bank.

Future IPPs might have to compete with a cost baseline that assumes low-cost hydropower from a neighboring country. Interconnections may also create new 11 Mwangi , KPLC presentation, op. cit.


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opportunities, as sources of potential new generation may be closer to customers in a neighboring country than they are to potential markets in the country of generation.

5. Financial Risks

5.1 Assessment of Finance Risks While Kenya has a robust banking sector with significant reach in rural areas, the rural electrification market is a challenging sector for many banks and finance agencies. Pipal Limited, a firm that finances projects in many sectors, identified the scale of renewable rural electricity projects as a major obstacle; the few renewable rural electrification projects that have been brought to the firm for financing have been too small to justify the transaction costs involved. Pipal also identified government bureaucracy as a key barrier, noting that individuals within agencies often do not stand to gain from projects moving forward. From a finance perspective, this leads to risk that projects that are technically sound and economically feasible might still not go forward due to difficulty in getting approvals from government agencies. Origins Venture Capital Africa, a new firm, identified the lack of grant support for project development as a major obstacle. While project developers have come to this company seeking project funding, they have not had the money to complete feasibility studies, making the commitment of investment capital difficult. Origins also noted that “tied aid,” whereby equipment or services from a particular donor must be used present an additional barrier to project financing, as a project may be required to use goods and services that are not ideal from an economic perspective. Barclay’s, a major commercial bank, noted that, while it is interested in renewable energy projects, the few that have been brought to its attention were not sufficiently developed to warrant commercial debt financing. The contact at Barclay’s noted that financing of renewable energy projects is still seen as a donor-led activity rather than a commercially viable business activity. In addition to securing project financing, arrangements that will enable rural customers to pay for power are a critical financial risk. A few players in the Kenyan banking sector have provided finance products to enable customers to purchase solar home systems; similar arrangements may be of interest to developers of projects where the technology hardware, not electric power, is sold directly to clients (whether community groups or households), such as with mico-hydro or biogas plants. This summary therefore includes information on customer finance options as well as on investment capital for projects.


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6. Overview of Finance Institutions and Agencies

6.1 Summary According to the Central Bank of Kenya and the Ministry of Co-operatives, there are many financing institutions in the country, as summarized in the following table12: Type of Institution Number Central Bank of Kenya 1 Commercial banks 55 Savings and Cooperative Societies 3168 Venture capital companies Many – exact number unknown Following are descriptions of the major finance institutions and agencies active in Kenya.13

6.2 Commercial Banks There are 55 commercial banks operating in Kenya, and 9 of them dominate the banking system. Most of the remaining banks are small and tend to concentrate on domestic and foreign trade, targeting well-established companies. Barclay’s Bank of Kenya, one major player in the country’s financial sector, is part of the UK’s Barclay’s Bank PLC and provides financing to many significant Kenyan companies. Barclay’s has in the past worked with Chloride Exide (the battery company) and with others to provide customer financing for solar home systems. Kenya Commercial Bank is the largest Kenyan-owned commercial bank. KCB has developed products to supporting lending for solar home systems but has otherwise not been involved in the renewable rural electricity sector.

6.3 Savings and Credit Associations (SACCOs) SACCOs are Savings and Credit Associations where people with a common bond (those who, for example, grow tea, an important cash crop in Kenya) join together to save regularly and build sufficient deposits for lending to group members. A few SACCOs, such as Harambee, Posta, and Mwalimu SACCOs, are larger than some small commercial banks. SACCOs are regulated under the

12 Commissioner of Insurance Report. Government of Kenya, 1997. 13 Overview of Consumer Financing Models for Energy. Stephen Mutimba, Energy for Sustainable Development Africa. August 2005.


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Co-operative Societies Act and have played a vital role in providing financial services to Kenyans. The growth of SACCOs over the last 20 years has been spectacular. The number rose from 630 in 1978 to 3168 by the end of 1997. This rapid growth is an indication that SACCOs are meeting a demand that is not being met by other financial institutions. SACCOs have played a key role in financing basic household needs and projects such as secondary school and college fees, emergency loans (for emergencies such as funerals), small house building projects, small business start–ups and modern energy products, etc.

6.4 Microfinance Institutions Microfinance institutions (MFIs) in Kenya date back to the late 1970s and early 1980s when it was determined that lack of access to credit (through the established banking sector) was strangling the large, informal, and important Small and Micro Enterprise (SME) sector. By 1998, there were over 86 NGOs and other organizations involved in providing microfinance. These institutions have proved, through a relatively low default rate, that the economically active SMEs are credit worthy. Many MFIs in Kenya today are undergoing expansion because of their proven track record with respect to successfully extending credit facilities and recovering loans. Key microfinance institutions in Kenya include the following: Kenya Rural Enterprise Bank (K-REP), Faulu Kenya, Equity Bank, Kenya Womens Finance Trust (KWFT), Wedco, Jitegemee Trust, National Christian Council of Kenya – NCCK, and Pride.

6.5 Development Bank The Kenya Rural Enterprise Program (K-REP) was set up by the Government of Kenya and the IFC to foster rural development. K-Rep focuses on small, organized groups of individuals that come together with a common cause. Community groups that wish to undertake a shared project, such as, for example, the desire to install a renewable energy community electricity project, may find K-Rep to be a promising source of funding.

7. Technical Risks In general, project developers seem to feel that technical risks are not as important as policy/regulatory and finance risks. There are some areas where technical risks are significant. Geothermal development, for example, is as expensive as oil and gas exploration, and this is one reason this resource has not been more fully developed.


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TANZANIA

1. Recent Projects and Attempts in Tanzania Tanganyika Electricity Supply Company (TANESCO) has been the key player in project development in electricity generation, transmission and distribution countrywide for both the urban and rural areas of Tanzania. Under the macro-economic reforms and in particular the power sector reforms, TANESCO is being commercialised and an open door policy on private sector investments in the energy sector is being encouraged. New projects that have started include the Independent Power Tanzania Ltd. (IPTL), Tanganyika Wattle Company Ltd. (Biomass-generated electricity), Kiwira Coal Mining Ltd. (KCL) are generating electricity that feed into the TANESCO’s grid under specific Power Purchase Agreements (PPA). Some mining companies and the four sugar factories in the country are expanding their generating capacity in order to sell surplus power into the grid.

On the other hand, the Ministry of Energy and Minerals (MEM) is establishing a Rural Energy Agency (REA) and a Rural Energy Fund (REF). Whereas the REA will promote and facilitate private sector investment in the energy sector, the REF will provide co-financing mechanism for eligible rural energy projects in terms of capital subsidies.

Parallel to the establishment of REA/REF, the World Bank is expected to finance a programme known as Energizing Rural Transformation (ERT) under which Priority Rural Electrification Projects (PREPS) will receive support. The ERT will equally support start-up projects known as “sub-projects” for the REA. Already, a list of 75,000 connections to TANESCO’s grid based rural extension projects in seven regions has been studied. A key consideration has been affordable connection costs through envisaged subsidies out of the REF. Business plans to that effect have been prepared. At the same time, initial five pre-feasibility studies for non-grid based electricity projects have been prepared. They are: 1. Mnazi-Bay gas to electricity project to cover Lindi, Mtwara and Masasi. 2. Mafia Island Biomass electricity generation project and 3. Three mini-hydropower projects in Kilocha, Njombe district, Mufindi in Iringa

region and Mngeta Village in Ifakara district.

Other late entries to be listed in the start up projects for study under REA and ERT initiatives include: 1. Two sugar factories belonging to Tanganyika Planting Company (TPC) in

Moshi and Mtibwa Sugar in Morogoro region. 2. Mini-hydro project in Kigoma Region on the Malagarasi River.


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Beside the REA/REF and ERT program, a Rural Electrification Study is being carried funded by the African Development Bank through TANESCO on behalf of MEM. The outcome of the study will among others include mapping of the potential energy resources and projects in the country for implementation in the medium and long- term future.

2. Highlights of Risks that Investors Face: Mini Case Studies Most rural renewable electrification projects face bottlenecks such as: • Location in remote areas making accessibility difficult. • Small projects or projects located far from existing grids and without

affordable own generation source thereby requiring high capitalization costs that make tariffs unaffordable to the local population.

• Inadequate transmission and distribution infrastructure. Some projects are expansive in nature and could be used to satisfy own power needs and sell excess to the national grid. They could also be used to not only support own work force requirements, but also the surrounding un-electrified village settlements. This is however impeded by the inadequate transmission and distribution infrastructure.

Below are three case studies that illustrate some of the challenges facing investors in renewable energy projects.

Case Study 1: Mafia Island Mafia Island is currently served by TANESCO through an isolated diesel grid. It faces specific challenges mainly because it is an Island district. TANESCO operates two 525 KVA diesel generators, generating approximately 1500 MWh per year. The TANESCO grid extends some 15km of 11 KV distribution, serving about 900 residential and commercial customers. Less than 10% of the island’s households are connected to the TANESCO grid. Mafia Island’s major enterprises generate most, if not all, of their own electricity. This can be attributed to the age of the generators, the weak condition of the transmission and distribution system, lack of spare parts and difficulties in supplying diesel fuel. The system is often plagued by shortages and unscheduled outages. Power supplies are limited in this fast-growing economy. A large fish-packing facility, a new prawn farm, a coconut plantation with processing facilities, and several tourist centres all meet most or all of their demand with their own diesel generating sets. Over 2.5MW of such capacity has been installed independent of TANESCO, with the price paid per KWh ranging from US$0.30 in the largest facilities to US$0.75 in those supplied by smaller generators.


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A private investor, the owners of the coconut plantation and facilities, approached the Ministry of Energy and Minerals (MEM) to request participation in the REA/REF as a ‘flagship project’ in 2003. Their initial proposal was to generate approximately 1 MW of electricity from wood and biomass waste (coconut waste) produced from their coconut plantation. Biomass would be supplied from wood waste from processing coconuts, and from the replacement of the 3,000 hectare plantation with other trees. While the number of consumers could conceivably be doubled on Mafia Island, the major objective of the proposed project is investing in an independent power production (IPP) facility powered by biomass, or one in which the biomass IPP is part of a new utility (possibly as a joint venture with TANESCO) with a 2MVA biomass generation plant (initially), an upgraded transmission and distribution system that connects all major customers (and supplies them with their needed electricity), and expansion of connections to new small industries (particularly small-scale fish packing and processing), institutions and domestic consumers. Project expectations include: • Reinforcement of existing grid and expansion by 18km of new 11KV

grid • 1000 new connections by 2015 • 6 GWh/yr for commercial use from 2007 • 1.7 GWh/yr (100 percent increase) for new domestic load by 2015 • 20 percent rural electrification by 2015

• Mainly renewable electricity by 2015

Biomass would provide base load generation, with diesel coming on for peak, in the initial days of the project. This would require approximately US$8 million in investment, and a grant-subsidy from the REF of US$3-4 million. The average tariff necessary to achieve an (Internal Return Rate) IRR of 20% would be approximately US$ .15 per kWh. Risks associated with the project include reliability of supply of biomass, high cost of connection, high investment costs, agreement with TANESCO on the use of its grid network among others.

Case Study 2: Mufindi Mini-Hydropower

The proposed Mufindi Hydropower sub-project is potentially a very


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attractive ERT and REF project. The region covered is currently supplied by TANESCO, but with poor capacity and frequent interruptions. Three important tea factories, Tanzania’s major paper and pulp facility, a number of businesses, and many institutions and customers are either currently served by TANESCO’s overstretched resources, or are not connected. Considerable self-generation (diesels) have been put in place by the tea factories (including pumps for irrigation) and other enterprises. The project area is a relatively densely populated farming area. Agricultural activities include tea farming, plantation tree cropping (eucalyptus, pine, wattle, etc.) and various subsistence farming activities. The estimated population of the project area is between 50 000 and 60 000 mainly in some 26 widely spread villages. The total number of TANESCO consumers in this district is about 2,700, thirty are classed as commercial or industrial (Tariff Codes T2 and T3) and the others are in the small customer category (Tariff D1). Total electricity sales during 2004 amounted to 21.5 MWh. Market assessment focused on expansion of electricity supply in the tea estates including meeting growing demand at the tea factories as well as supplying power to out growers, residents, and villages on and near the estates of Mufindi Tea Company and Unilever Tea Limited. The two tea estates (MTC and UTL) together currently consume approximately 11.5 MWh per annum, and are experiencing growth of approximately 10 per cent per annum – a growth rate they expect to continue in the coming years. Both estates use diesel generators as back up during the frequent power outages, and operate diesel generators at unelectrified sites on the estates. One tea company -with two tea factories in the area- operates a number of diesel pumps for irrigation purposes, and would like to convert to electricity to replace the diesel fuel consumption of approximately one million litres per annum. A load forecast has been prepared including existing load at the estates, load growth at the tea factories, conversion of diesel pumping to electricity, and electrification of residents on the tea estates, out grower villages associated with the estates, and villages near the proposed new 33 KV line.

The potential for stimulating economic growth through this sub-project in this fast growing, important economic area, is considerable. There is also great potential for a good public-private partnership between the project sponsors and TANESCO, both through the proposed model of wheeling power from the hydropower scheme, as well as the purchase of TANESCO power during periods of peak demand. Several public-private


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options exist, from franchising and leasing (wheeling, distribution, etc.) to joint venture.

The proposed sub-project consists of establishing a generation and distribution company, with distribution activities mainly on tea estates (to their workers and surrounding villages). The project would install a 3MW hydropower turbine on the Mwenga River. It proposes distribution on tea estates and nearby villages, and wheeling electricity across the TANESCO grid to key customers (namely two other tea estates). The proposal also envisages purchasing power from TANESCO to supplement own production at peak times. The major points of the proposed sub-project are:

• 3000 new connections by 2015 • 23 000 GWh/yr available to support growth in agricultural activity • Replacement of diesel irrigation pumps (operated by two tea factories)

with electricity

• Improved reliability of supply in the district

• Accelerated economic and social development through availability of reliable and plentiful electricity.

This calls for US $4.5 million in capital investment, generation and distribution to make it work. Its estimated unit cost of supply is approximately US $0.034/KWh (excluding distribution). Major risks are associated with sources of financing, agreements to wheeling of power in the TANESCO’s grid at attractive tariffs, the cost of connection to rural households and affordability.

Case Study 3: Njombe Mini-Hydropower

Kilocha Mission in the South-eastern part of Njombe District, Iringa Region, is promoting a sub-project to expand hydroelectricity generation. They have formed a company, Matembwe Vocational Company, which operates a small hydropower station and isolated network in the project area. They wish to expand this to develop a grid supplying the project area, including three church missions, four villages and one tea estate. Their sub-project proposal calls for development of a hydroelectricity plant of some 4.6 MW generating capacity, with distribution to load centres in project area and 1,500 new connections by 2015. The project would lead to replacement of silted hydropower station at Matembwe and displacement of diesel generation at the tea factory. The project calls for US$11.6 million in capital investment, generation and


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distribution. The projected unit cost of supply is approximately US$0.18/KWh excluding distribution. The hydropower project requires a subsidy of US $7 million and the grid extension project requires subsidies of $1.7 million.

A key concern for this project is that it is likely to be interconnected to the TANESCO grid in the near future. The proposed capacity of the hydro generation unit far exceeds demand in the area, and, would lead to a very high unit cost per consumer. It is unlikely that TANESCO with its rapidly growing natural gas electricity generating capacity, would wish to invest in this hydropower plant, and certainly would not be willing to pay a purchase price to the investors that would ensure cost recovery on the hydropower investment. Thus, there are a number of risks that make investment in the hydropower site difficult to justify.

However, there is a good case for the existing Matembwe Company to go forward with setting up a distribution company in partnership with TANESCO. They could mobilise the community and the businesses in the area and prepare for grid connection with TANESCO. They could apply for a grant/subsidy from the REF to develop the distribution network, and to operate this, perhaps as a concession with TANESCO. The existing company certainly would be able to aggressively add new customers, and would probably deliver electricity at considerably lower costs through innovative management, operations and distribution options.

3. Policy and Regulatory Risks The energy sector reforms make a distinct separation of policy, regulatory and commercial responsibilities, as briefly summarised below:

Policy: The MEM has responsibility for setting and reviewing

policy and strategy as set out in the National Energy Policy and the National Energy Strategy through issuance of directives and guidelines. This is in line with international practices pertaining to government role and functions that would prevent conflicting policy direction of the sector. How effective implementation of policies take place could be burdensome to investors.

Regulatory:

Up until recently, MEM has been regulating the sector in terms of issuance of license to power companies, tariff setting and tariff regulation. However, aware of the need to have an independent body regulating the sector in the wake of reforms taking place, an Energy and Water Utilities Regulatory Authority (EWURA) is being


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established to take over those functions. The modus operandi of EWURA is still an uncertainty since some regulators could be a bottleneck to investors- and could therefore be perceived to be applying brakes on development initiatives

Commercial Operations:

The government liberalization policy allows for the participation of new (other than TANESCO) and private entities in activities of energy service provision including rural energy services. Currently, investment in rural energy projects has been low keyed mainly due to lack of clear policies, the perceived new role of TANESCO’s monopoly status after being restructured, in the generation, transmission and distribution of power countrywide and the high cost of investment vis-a-vis low economic and financial returns on investment, among other factors. However the ongoing power reforms open the door for commercial operations to be managed by the private or commercial energy companies including TANESCO. In order to allow for entry of the private sector in the management of commercial activities, the following strategies are being implemented by the government:

3.1 Restructuring and Unbundling of TANESCO

The existing vertically integrated monopoly structure of TANESCO is being reviewed to allow for creation of ring-fenced business units for power generation, transmission and distribution. The government has contracted out, management of TANESCO to commercialise the company in terms of attaining financial stability and improve technical performance to enable privatization of viable units. It is envisaged that TANESCO will be split into three generating companies, one transmission company, two distribution companies, a core company and a holding company.

Among the risk factors associated with the impending privatization are that the newly formed companies might establish a monopoly position themselves.

3.2 Rural Energy Agency (REA) and Rural Energy Fund (REF)

TANESCO’s mandate includes electrification of rural areas. However, as a result of restructuring, the MEM sought to establish an agency for promoting and facilitating private sector led and community based initiatives for investing in rural energy. To this end the REA and the REF have been established under a


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parliamentary Act of Establishment of April 2005. The REF is a financial mechanism that will be confined to eligible rural energy projects. It provides capital subsidies for the initial up-front costs of capital investments in the energy sector (once-off “smart subsidies”/grant) which could significantly reduce risks to project developers and financiers.

Projects supported by REA/REF will not be “one-off” stand alone ventures, but those that demonstrate to investors, financiers and other stakeholders the potential benefits of every investment for rural access and productive use. The idea is to reduce risks and encourage the private sector to invest in, and the financial sector to lead to, such ventures. The approach is expected to propel and achieve economies of scale and lower transaction costs. It will multiply the impact of the REA/REF activities.

Competition shall be the operating principle in the selection of projects for financing, based on maximum economic efficiency at the least cost possible to consumers and relative high returns to investors. REA will encourage the private sector to take the lead in development of projects for REF support. Where the private sector is slow to take initiative particularly in high priority areas, REA itself will develop project concepts and tender them to the private sector in an appropriate competitive procedure. Award of subsidies will be used for the most competitive projects i.e. the one with the highest long term socio-economic impacts per unit of subsidy.

3.3 Tariff Reforms

The government desires that rural consumers be provided with electricity services at lowest cost possible whereas the real cost of provision of services is always the opposite. Energy reforms dictate the use of cost reflective tariffs which implies the application of regional differentiated tariffs as opposed to pan-territorial uniform tariffs. The key question that needs to be addressed is: to what extent should tariffs reflect costs? In this regard, and to overcome the imbalance, subsidies are made to bridge the gap. However, to be effective, subsidies need to be designed and monitored carefully to accelerate the pace of access expansion for the utility companies and the private sector.

Currently, the utility company (TANESCO) practices a form of cross subsidy such that industrial/commercial consumers pay more for electricity than domestic customers. This form of tariff cross subsidy is made for socio-political considerations. The tariff structure includes a lifeline block providing a low tariff for the initial 50 KWh of monthly electricity consumption. It is targeted to benefit poor households’ who happen to be low consumers. All domestic consumers are beneficiaries of the low price tag.


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At the same time, the uniform national tariff being applied in Tanzania implies cross subsidization, and has a direct economic benefit to consumers in areas with high supply costs particularly in remote regions not connected to the grid. The effect of these subsidies is often mixed. These subsidies are also applied when the pricing of electricity remains constant during peak and off-peak periods. In this case, off-peak consumption at a lower cost of production subsidizes the peak consumption. Time differential pricing may be designed to reflect the variation of costs by time-of-day, in order to change and manage consumer consumption pattern. Time-of-use tariffs have the advantage of reducing electricity generation requirement and consequently the tariff payable by the poor.

Another type of subsidy relates to the cost of connection or access subsidy. This can be provided for the entire connection cost or part of the cost with the balance carried over to the monthly bills depending on the financial capacity of the subsidizing company or firms. Currently, TANESCO provides connection subsidy by way of monthly payment through instalments. Under the ERT, there is also a window for funding access costs for both grid and non-grid connection. (This shall also be so under REA/REF).

Under the ongoing reforms, all tariffs of transmission and distribution systems are subject to approval by EWURA. The same applies for generation services unless EWURA determines that competition has become effective. EWURA shall establish procedures and standards for approving, modifying or disapproving the elements of the multi-year tariffs formula. Rates or charges for power sales shall among others, protect consumers against monopolistic prices and practices, permit licensees to recover the efficiently incurred costs and earn a fair return on equity, reflect subsidies that the government may have authorised and encourage economic efficiency within the sector by sending accurate price signals regarding the relative abundance or scarcity of supply. The EWURA Act does not exclude the possibility of having a distinct tariff system in different distribution areas.

On the other hand, since the tariff structure is a crucial element for the financial viability of a rural electrification project, EWURA will have to address the issue of adopting a uniform national tariff system for the whole country with regard to operators with both TANESCO and other operators against various tariff systems with regional differentiation. EWURA would also look into acceptability of cross subsidies between customer groups and subsidies on investments for the Rural Energy Operators. Various services models could be considered depending on impact on TANESCO customer connection and subsidy requirements. These include: existing TANESCO tariff including the LUKU model (prepaid), low cost KWh billing model for the residential sector with consumption limits, based on a limited per day consumption of KWh at fixed monthly prices, offering lower connection costs and a simplified revenue collection procedure without metering or a flat rate tariff for domestic customers on monthly lump sum for the required


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service provided by operators through ready boards (with pre-financing of connection and standard equipment.

3.4 Investors Guide in the Energy Sector Major steps that would guide investors include the following:

• Project Identification and promotion: Currently needs MEM’s support and

backup. Later need the backing of REA/REF. Government bureaucracy has always been an issue of concern.

• Preparation of Feasibility Studies: Investors may fund this or could be

jointly funded by the MEM and Investor. Aware of the unattractiveness of rural based projects, MEM has been funding for studies and projects through TANESCO from annual budgetary allocations.

• Project Appraisal: Currently done by MEM but later REA/REF will take-up

the role. • Project Funding: Most rural projects have been funded by the government

through government or donor funded projects. Future projects would be private sector sponsored and would draw from the REF co-financing in terms of grants on capital cost. The amount of grant would depend on the nature of the project and availability of funds as well as the decision of the Rural Agency Board.

• Government Guarantee: Government has been and could provide

guarantees on Power Purchase Agreement with TANESCO under negotiable terms. This protects investors against possible risks on power generated to be fed into the national grid. Disputes on PPA’s are common.

• Business Licenses: These include Company Registration License under

Caps 212 given under the Company Registration Ordinance and Municipal Trading Licenses which need to be processed and issued. Issuance of licenses is subject to meeting specific conditions such as safety measures in place or security concerns.

• Power Generation Licenses: Currently, the MEM issues these but the

regulatory functions will be passed over to EWURA. How the regulator will treat this matter is subject to the future.

• Project Financing: Equity and Loan from financial institutions at negotiated

interest rates. These currently range from 13% - 16% for TShs. and 6% - 12% on foreign currency.


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• Land and Water Rights: Investors have to channel these through the

appropriate authorities under the existing Acts. • Building Construction Works: Need the Local Government approval and

permits. • Equipment Procurement Standards: Currently done by the Tanzania

Bureau of Standards (TBS) but this function to be undertaken by EWURA in future.

• Determination of Tariffs: Currently done by TANESCO but will be taken up

by EWURA. • Employment of Consultants and Contractors - Investors: Under the REF

subsidy REA would need to sanction appointment.

4. Financial Risks Investors in renewable energy face problems of accessing project funding due to the high risks associated with rural project lending, particularly for rural electricity ventures, it being a new concept in Tanzania. This lack of experience on the success/failure rate discourages financiers’ entry to support such types of ventures. Most long term loans from financial institutions have the following characteristics that create financial barriers to potential investors:

Credit period Up to ten years. Grace period for payment of both interest and

principal may be agreed but it cannot exceed 1 year from the dateof first disbursement.

Interest rate The prime lending rate is currently 19% p.a. There is room for negotiation.

Disbursement Tranches or single instalments directly to the suppliers Repayment source

Proceeds from the business itself. Alternative legal repaymentsources may also be accepted.

Equity contribution

This is mandatory as it shows the owner's commitment to the business/transaction. The owners' commitment should at least be25% of the total investment cost.

Collateral Requirements

This is the basic requirement. No credit can be granted withoutcollateral. Collateral is the second dependable way out. The collateral must have the following attributes: Legal title


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Easy to value Marketable Different types of security include: Legal mortgage overimmovable assets, chattel mortgage over movable assets,treasury bills, treasury bonds, fixed deposits, unconditional government guarantees, first class bank guarantees, standbyletters of credit, shares for listed companies. Where there is a third party guaranteeing the credit with theguarantee supported by cash or near cash collateral, a risk sharing arrangement say 90: 10, 80:20, 70:30, 60:40, 50:50between the Guarantor and the Bank may be accepted dependingon the level of risk involved. Note: Chattels are not taken as sole security. They are onlyaccepted as additional security. Non traditional collateral assets which do not have legal title cannot be taken as security.

How is credit worthiness determined?

Creditworthiness is determined through a thorough appraisalaiming at establishing the ability to pay and willingness to pay. Areas of special concern include: Past performance and experience Legal risk Financial risk Management risk Collateral risk Market risk Business risk

How is nonrepayment handled?

The first dependable way out is the the business. Recovery is through the business itself. Where the business fails to repay the loan, the bank can go for sale of security assets. Recovery is done through CRDB Bank Branches or centrally through the Loan Recovery Unit at Head Office. Recovery is done through negotiation with defaulters, sale under power of mortgage/debenture, or through court cases.

Discussions with a number of Banks in Tanzania indicate extremely low engagements in rural finance projects. For example; the Cooperative and Rural Development Bank were only involved in financing the labour based contractors in Mwanza region and then, only under the UNDP guarantee arrangement. The experience was positive mainly because the borrowers were assured of allocation of road projects whose earnings were used by the contractors as a source for the repayment for the loans. Contract proceeds were routed through


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the CRDB Bank Branch in Mwanza enabling it to recover the loan instalments. The risk arrangement sharing was put at 60:40. Among the 9 customers granted the facility, there was only one default that was attributed to character that prevented that contractor from obtaining new construction work from the project.

Another past experience has been government intervention in solving acute transport problems facing 7 regions in the country for lack of private sector involvement attributed to poor infrastructure during the 1980’s up to the early 1990’s. Regional Transport Companies were formed under the World Bank funded project (SD 15 million) known as Trucking Industry Rehabilitation and Improvement Project which later also received Japanese grant assistance totalling to about 2.0 billion Yen. These funds were channelled through the Treasury Register which paid out to the 7 established transport firms on a pro-rata based on the determined fleet size. However, the financing was on an equity and loan from Treasury Registrar on a 1:1 basis repayable over a 5 year period. The above measures were put in place due to the reluctance of the financial institutions to extend credit facilities. Possibilities for replication of such funding by government on a PPA basis could be investigated.

Under the current energy sector reforms, a number of measures are in place or are in the pipeline to address part of the financial risks that would be attractive to investors. These include:

• Establishment of REA/REF: Under which project grant funding will be

available to specific projects. During the financial year 2005/06 TShs. 2.4 billion has been set aside by the Government to start off the operations of the Agency and Fund. Future funding is expected from both the donor community (Development Partners) and government support.

• Energising Rural Transformation (ERT): The World Bank is expected to

fund low cost TANESCO grid extensions covering about 200,000 new connections. The connections also include isolated grids in the country. A total of up to US $ 80.0 million is expected to be made available starting mid next year.

• Church organizations: Investors in the renewable energy sub-sector that

have expressed interest include church organizations such a Kilocha in Njombe district of Iringa region who are seeking grant assistance and providing equity if possible in cash and kind. Others are Agricultural Project such as in Kilombero, Mngeta project in Morogoro region.

• Co-financing: Credible investors at the current stage could come in on a co-

financing basis with TANESCO who have already built a reputation and experience in the project. The fact that investors can enjoy tax holiday under the Tanzania Investment Centre (TIC) approval mechanism should attract


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private energy operators’ investment. A tax holiday for power project is 15 years whereas for other industries it ranges from 5 – 7 years.

Other tax exemptions offering financial relief include:

• Exemption of import duty for export oriented industries as against

other industries. • Avoidance of double taxation of foreign investors on the basis of

bilateral agreements. • Tax exemptions on royalties and technical know how fees received

by any foreign collaborators, firms, companies and experts. • Tax exemption on the interest of foreign loans.

5. Technical Risks Perspectives and requisites for private sector sources of finance and investment to increasing rural access revolve around two major issues:

• Commercial risks and • Capacity issues

As earlier noted, accelerated access requires cost reductions, an expanded revenue base and the application of “smart” investment subsidies. Efforts to reduce access cost would demand review of prevailing outdated technical standards of electrification and practices borrowed from Europe in favour of locally acceptable ones as approved by the Tanzania Bureau of Standards (TBS), Engineers Registration Board (ERB), and the Contractors Registration Board (CRB). It would also include the initiatives being undertaken to review the existing Electricity Law.

On the other hand, the cost effectiveness of projects can be enhanced by use of proven low cost technologies which include among others the following:

• Ready Boards • Aerial bundled conductors • Single Wire Earth Reforms System (SWER) • Shield Wire • Etc.

Competitive bidding procedures in implementing projects could also reduce construction and installation costs.

The key issues that need to be noted on technical issues include:


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• Compatibility with existing facilities • Expendability • Versatility • Sealing features (tempering resistant sealing facilities) and • Approval i.e. meets national specifications and where relevant, carries

the SABS mark.

The major challenge is the fact that TANESCO or its successor might remain a major player in the power sector at the current level and at the levels being planned for and that the private sector will co-exist with TANESCO. Already, TANESCO is contracting out services to the private sector e.g. design, construction and maintenance of network through competitive bidding. TANESCO will also be a key player in setting engineering standards/approaches for low cost electrification technologies which can be availed to the private sector investors. TANESCO will also undertake supervision of engineering, construction and erection works (… with consultants). There exists a possibility for bulk supply sales to private sector operators. In effect, there is need to address barriers to new investors entering electricity distribution market by adopting the following measures:

• Liberalize access to TANESCO’s grid to accelerate access pace e.g. by bulk

supply customers, SMES participation in construction and installation projects.

• Create a “level playing field” for competitive and efficient distribution,

expansion for various players, International Trading Organization standards, transparent bidding processes etc.

• Address capacity building to local SMEs so that they can effectively

participate in PPA programmes (jointly with ERB, CRB, and NEMC). • Provide information for business development services to enhance

communication. • Address financing barrier with credit or equity support mechanisms.

6. Other Factors Power Purchase Agreements: Power Purchase Agreements (PPA) has been used in the IPTL and Songas Projects to help mitigate the risks of investors in developing power projects. However, the Electricity Trading and Arrangements Study prepared by Mercados Energeticos in 2003 indicates that, in the application of the power purchase agreements, the risks are not shared but all risks are borne by the government.


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A key recommendation of the study is that cost sharing is necessary. This is because the main objective of power sector reforms is to encourage private participation and competition. However, it is considered essential that measures be taken to explore specific guarantee instruments for maintaining or restoring confidence in the power infrastructure development. Construction Completion Risks: The government may have to outline its policy regarding risk sharing in the power sector. Such guarantee should cover the construction completion risks, in which the government will cover any costs resulting from any delays caused by a mix-up on the part of the government. The guarantee should be in the form of contractual provisions and/or other commercial instruments. Fuel Risk: The option to cover risks associated with a rise in fuel costs may be explored, on a case by case basis. However, such guarantee by the government is only possible if the fuel supplier is a state-owned company.

Political Regulatory and Current Risks: Political risks that impinge upon the performance and revenue earnings of the private investor can be guaranteed. Guarantees against regulatory risks should not be entertained as they may be discriminatory among the various investors in the same sector. Guarantees should not cover force majeure.

Environmental costs: The production of electricity often has significant environmental costs. However, the consideration of costs arising from negative environmental effects of power projects in the price of electricity is hardly accepted as common practice in Tanzania.

The exclusion of environmental costs makes electricity cheaper than it would have otherwise been. Thus demand for electricity is higher than it would have been if these costs were accounted for in the price. The environmental damage from this incremental amount of electricity consumption is attributable to the subsidy that arises from the exclusion of environmental costs. Policy Platform, Risks and Rewards for Investors: The roles of various players i.e. government (policy, facilitation and promotion of private sector), regulators and the political and business leadership (providing information to investors and sensitive taken to invest) and responsibility of the civil society needs to be clarified and well defined.

Equally the policy platform for the various stakeholders/investors to have a common agreement for fair competition, regular consultation, transparency in information and abiding to the national legal and regulatory laws is an essential element in risk mitigation measures.


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UGANDA

1. Recent Projects and Attempts in Uganda While the potential of renewable energy to contribute to energy needs in the region has not been fully realized, a few significant developments have taken place. The role that renewable energy technologies can play in rural electrification is receiving greater recognition. The World Bank’s ERT programs in Uganda are developing government infrastructure for effective rural electrification and are making funds available to project developers. As part of a policy to stimulate economic growth in such areas, the Ministry of Energy and Mineral Development has put in place a program of awarding concessions to private developers to generate and supply electricity direct to consumers. These concessions are based on taking over the existing isolated generation and distribution facilities and then increasing the number of customers’ connections in line with pre defined targets. This will require the growth concession holders to develop new generation sources to meet the load growth. Rural hydro projects will form an important component of this process. The developers who have shown interest in investing in rural energy include the following;

1) Kakira Sugar Works 2) West Nile Rural Electrification Company (WENRECO) 3) Hydromax LTD. 4) Kilembe Investments (U) Ltd 5) Mt. Elgon Power Company. Ltd (MEPCL) 6) Sugar Corporation of Lugazi (SCOUL) 7) SN Power of Norway 8) Electricity Distribution Management (EDM) of Namibia 9) Uganda Sustainable Energy Company (USEC) 10) Uganda Energy for Development Co. (UERD). 11) Kisiizi Hospital Power Company Ltd 12) Adjuman Rural Electrification Co. Ltd(ARECL) 13) East African Technology Development Network(EATDN) 14) Ntenjeru Power Company Limited. 15) Kagera Ecocites Ltd 16) Katonga Power Co. Ltd 17) Victoria Electricity Supply Co. (VESCO) 18) Kabale Power Company 19) Bamwiine Hydro Power co Ltd


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20) Energy Africa

All these companies are in one way or another in the initial stages of trying to invest in rural power development except Kakira Sugar Works Ltd and WENRECO, who are already in the business of producing and selling power.

2. Highlights of Risks that Investors Face: Mini Case Studies

Most rural renewable electrification projects have faced problems associated with take off because of being located in remote areas and therefore face accessibility difficulties. Some projects are too small or are far from existing grids and therefore require a lot of capitalisation cost to set up. This raises tariffs which in turn makes the electricity unaffordable to the local population.

Case Study 1: WENRECO

WENRECO’s project description entails the sale of electricity in Arua and Nebbi districts of West Nile. The company signed a concession agreement to manage electricity generation, transmission, distribution and sale in Arua and Nebbi districts. It took over the old plant of UEDCL that was generating for 4 hours but is now generating for 18 hours a day. It has commissioned a new generator of 1.5 MW running for 18hrs and also embarked on the rehabilitation and extension of the distribution network system to Paidha and Nebbi. The company has plans to develop a 3.5MW power plant at Nyagaka.

The project’s projections include: • Increased client base from the current 1,200 customers to 1,700

customers. • Production of 3.5MW after Nyagaka Dam. • Electrification of two districts in Nebbi i.e. Arua and Pakwach. • Construction of 11KV distribution of 50KM line to Koboko. • Better standards of living in the area due to the reinforcement of

existing grid and expansion by 20km of new 11kV grid in the project area.

• Approximately 1,500 new connections by 2015 • Two villages would be connected to electricity supply. • Supply of electricity could spur commercial and agricultural

investments in the area, which is very fertile. Constraints: WENRECO signed the concession in 2003 and therefore ought to have started on the development of Nyagaka hydro. However, they have stalled because:


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• The original market assessment was overestimated and this has changed

the progress of further investment in the project. • The poverty levels in the areas in Arua, Nebbi and Paidha pose so high a

risk that even calculated investment would not bring high returns. • High cost of construction and high investment costs of distribution lines to

Moyo

Case Study 2: Kakira Sugar Works

In 1889, Kakira agreed with the G.O.U to produce power from bagasse and use it at their sugar factory. They installed a1.5 MW turbine. The cogeneration project producing power from baggase have upgraded and commissioned two turbines each producing 3MW totaling to 6MW. They have also imported a turbine of 16MW that will give them a capacity of 22MW after its installation. The project is expected to cost $20million So far an investment of over US $10million has been made, of which US $7.7 million is a loan from ERT, US $0.6 million from EADB and US $3.3 grant from GEF. The balance is to be provided by Kakira sugar works The factory and Kakira consume an average of 8 MW and the balance is sold to UETC ltd with whom they have signed an agreement for the supply 6MW. Kakira also have an agreement with the Ministry of Energy to supply 12MW off-peak for 18hrs

Project expectations include: • Increased acreage production in sugar to 22,000 acres and 40,000 out

growers • Increased sugar production from the current 90,000tons per year to

150,000 tons per year that will lead to reduction in importation of sugar and sugar prices.

• Increased employment in cogeneration, in sugarcane growing and in out growers schemes already 100 people are employed in cogeneration

• Production of 22 MW of power which will be put on national grid will reduce on shortage of power in the country.

• Two villages would be connected to electricity supply. • Supply of electricity could spur commercial and agricultural

investments in the area that is very fertile.

The major risks associated with Kakira sugar works have been the reliability of supply of bagasse, high investment costs, agreement with UETCL on the use of its grid network, and the tariffs to be charged and the government’s guarantee on the power purchase agreement because the


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one signed with UETCL was originally for 8MW whereas now, they are in the process of producing 16MW.

Case Study 3: Hydromax

Hydromax is expected to generate 10MW hydropower at River Wambalya in Buseruka, Hoima and distribute it to Hoima, Masindi & Kibale.

The following has been accomplished so far: • Feasibility studies completed • Review of feasibility study for project optimization. • Obtained required license from ERA and NEMA, as well as Water Use

Right and Water Abstraction Permit. • Business plan for the 1st phase of investment reviewed • Submitted draft PPA to UETCL • Submitted subsidy and credit facility to ERA, REA and MEMD

Project expectations:

• Electrification of Hoima, Masindi & Kagadi Districts • Construction of 280 Km of HV distribution lines and electrification of the

following areas: 1.Hoima – Kagadi 2.Kagadi – kijwiga 3.Katoke –Kyarushozi 4.Hoima –Buseruka 5.Masindi –Wasendo 6.Masindi- Hoima

(a) 90,000 Customers will be connected at the end of the project The major risks associated with the Hydromax project are: (b) High investment costs, (c) Agreement with UETCL on the use of its grid network and the tariffs to

be charged, and (d) The governments guarantee on the power purchase agreement and (e) The hydrological risks of the river where the water levels can be

extremely low.

3. Policy and Regulatory Risks In the medium term (2005/06 – 2007/08), the main policy priorities stated in the Budget Frame work Paper (BFP) by the ministry of Energy and Mineral Development were to:


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• Put in place policies and laws, which will enable private investment and capital inflow into the energy and mineral sectors

• Increase electricity generation and rural electrification • Stabilize the prices of petroleum products and achieve security of supply • Conduct petroleum exploration and development in order to achieve local

production. The privatisation and liberalization of the power sector represents a major shift in Uganda’s energy policy. The implementation of this paradigm shift has however proven to be problematic, calling for compromises that partly go against the original hopes of genuine private sector led development Subsidies to Rural Electrification The energy sector reforms started with the Electricity Act of 1999, which set the legal basis for the industry’s restructuring. In 2001, the government functionally unbundled UEB into separate generation, transmission and distribution companies. The assets liabilities and operations of UEB were transferred to: • Uganda Electricity Transmission Company (UETCL), which has a key role as:

(i) Owner, investor and operator of transmission power lines (66 kV lines and above) in the country;

(ii) Single buyer for grid connected generation, which is sold on to the distributors; and

(iii) Power expansion planner. • Uganda Electricity Distribution Company (UEDCL), who is owner of the

interconnected distribution assets owned by the state and monitors the concession (asset maintenance) of Umeme. UEDC still operates three small concessions and maintains the rural electrification schemes funded by SIDA and implemented by MEMD. UEDCL has a staff of 9 professionals, and 5 support staff.

• Uganda Electricity Generation Company (UECGL). The main task of UEGCL

is to monitor the maintenance of state-owned generation assets that have been leased to Eskom, as well as the construction of Kiira. The business plan of UEGCL -which still needs to be approved by the Board and afterwards by MEMD- proposes to rehabilitate small hydropower plants and to construct new small hydropower plants. Funding would come from the financial surplus UEGCL makes on interest rate income for the lease fees it receives before they are passed on to the state budget.

The government opted for long-term concessions for the generation and distribution businesses and decided that, in the interim, responsibility for transmission would remain with UETCL, which would operate as an independent and profit making business unit.


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The Electricity Act 1999 established the Electricity Regulatory Authority (ERA), and its members were appointed in June 2000. They are responsible for setting up an effective secretariat manned by competent professionals to regulate the industry independent of the Ministry. The Electricity Act 1999 provides ERA with clear statutory authority. Its budget is separate from that of MEMD. For rural electrification, the new framework is composed of the Rural Electrification Agency (RE Agency), the Rural Electrification Board (RE Board), and the Rural Electrification Master Plan (RE Master Plan). In accordance with the Act, the moneys of the fund shall consist of:

• Appropriations by the Parliament; • Any surplus made from the operations of the ERA; • A 5% levy on bulk purchases of electricity; and • Donations, grants, and loans acceptable to MEMD and MFPED.

Generation and distribution is in the hands of the private sector on 20-year concessions, with cost-of-service regulation. The costs are based on written-down asset value increased by additional investment. The distribution concession was transferred to Umeme in March 2005. The new company, Umeme, is 56% owned by Globaleq, an emerging markets power company and subsidiary of CDC, and 44% by Eskom. Eskom Uganda (a subsidiary of Eskom Enterprises, the holding company for Eskom's non-South African business interests) won the electricity generation concession in late 2002. Under the 20-year concession, Eskom is responsible for all the power generated at the two dams in Jinja. The AGRECO company in 2005 won the tender to install, operate and sell energy from a new 50 MW diesel power plant, urgently needed to meet peak power demand. MFPED has to authorize the removal of taxes on fuel and pay the capacity payment.


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3.1 Summary of Political and Regulatory Risks

REA has not yet defined a subsidy policy for rural electrification. Decisions by REA on subsidies to support rural electrification projects have so far been taken ad hoc without reference to well-defined principles. This has resulted in very highly subsidized rates: an example is the award of a US$3.3m grant out of a cost of US$4.3 m for the bagasse-power plant at the Kakira sugar mill. The problem with these rates is that the projects that have been supported so far are among the “best” type of projects that are likely to be encountered in rural electrification. The highly subsidized rates, therefore, have given wrong signals to potential investors as to the level of subsidies and tariffs they can realistically expect. If REA continues to provide such highly subsidized rates, the volume of annual rural electrification will be far below target and politically acceptable electrification rates.

The role of district authorities in the identification and implementation of rural electrification projects is also not yet clear. District Development Plans do not include energy as a component. Part of the problem is that MEMD, unlike the health, water and education ministries, does not have local representatives on the ground in these region hence impeding the private investors efforts at conflict resolution on the ground. Ugandan law (The Electricity Act cap 145) provides for the participation of the private sector in the electricity sector. A private investor seeking to set up an electricity project approaches the Electricity Regulatory Authority and lodges a notice of intention to apply for a license. It is the license, which is instrumental in ultimately giving authority for an investor to proceed with his project. Key conditions for the application of a license include satisfactory technical design, financial plan, commercial proposal; NEMA approved Environmental Impact Assessment Report and other permits such as water use, local government, and e.t.c.

3.2 Tariff Reforms The government’s ideal is that rural consumers be provided with electricity services at the lowest cost possible. However, the real cost of provision of services is always the opposite. Energy reforms dictate use of cost reflective tariffs, which implies application of regionally differentiated tariffs as opposed to pan-territorial uniform tariffs. The key question that needs to be addressed is to what extent tariffs should reflect costs. In this regard and to overcome the imbalance, subsidies are made to bridge the gap. However to be effective subsidies need to be designed and monitored carefully to accelerate pace of access expansion for the utility companies and the private sector.


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Currently, the Electricity regulatory Authority (ERA) decides on the tariffs to be charged.

On the other hand since the tariff structure is a crucial element for the financial viability of a rural electrification project, EWURA will have to address the issue of adopting a uniform national tariff system for the whole country with regard to operators.

3.3 Investors Guide in the Energy Sector Ugandan laws (The Electricity Act cap 145) provides for the participation of the private sector in the electricity sector. A private investor seeking to set up an electricity project approaches the Electricity Regulatory Authority and lodges a notice of intention for the application of a license. The Act provides for the procedure to be followed, leading to the award of a permit. It is the license, which is instrumental in ultimately giving authority for an investor to proceed with implementing the electricity project. Key conditions for the application of a license include satisfactory technical design, financial plan, commercial proposal, NEMA approved Environmental Impact Assessment Report and other permits i.e. water use, local government, etc Major steps that investors have to go through include the following:

• Expression of interest to REA on concept development and site. • Obtaining a permit from the Electricity Regulatory Authority (ERA) to

undertake studies. • Carrying out feasibility studies with an option of applying for a grant

from Electricity for Rural Transformation BUDS/PSF Project. • Submission of a formal application including studies and business plan

to REA indicating subsidy requirements. • If proposal is feasible negotiations and signing of a subsidy agreement

and obtaining a letter of comfort from REA. • Attaining a financial closure with banks and other relevant institutions. • Obtaining an operating license from ERA • Implementation. • Monitoring and evaluation carried by REA

Other procedures the investor include:

• Project Identification and Promotion – Currently, this is being done by the investors with the support of MEMD. Government bureaucracy and delays is a major impediment.


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• Preparation of Feasibility Studies – Investors are doing this with the help of the Private Sector Foundation who are providing 50% of the funds required. The Private Sector is using funds from World Bank ERT project.

• Project Appraisal: This is currently being done by REA /REF. • Project Funding: Most rural projects are either funded by the government

or donors. The private sector with the help of government subsidy drawn from the REF and ERT are accessing the funds for developing the rural areas. The Amount of grant is dependent on the nature of project and availability of funds as well as the decision of the Rural electrification Agency.

• Government Guarantee: The government has been and could continue providing guarantees on Power Purchase Agreement with UETCL under negotiable terms. This protects investor against possible risks on power generated to be fed into the national grid. Despite this, disputes on PPAs are common.

• Business Licenses: These are issued by ERA. But others like Environmental Impact Assessment licenses are issued by NEMA, Water use permit by the Ministry of Water and Environment e.t.c. Issuance of licenses is subject to meeting specific conditions such as safety measures in place and security concerns.

• Project Financing: Equity and Loan from financial institutions is usually done at negotiated interest rates. Currently, these range from 18% - 23% for Uganda Shillings

• Determination of Tariffs: Presently, these are done by ERA.

While Uganda has made changes in the power sector structure, at present the regulatory environment needed for the independent grids many of which would generate power from renewable energy resources, is still to be developed. In line with this, there is need to streamline the processes and requirements such that they create a one stop center from where the private investors can get the necessary requirements for investing in this area instead of moving from one department to another. There is a lot of bureaucracy in government offices, which discourages/frustrates potential investors. For example, it takes almost 180 days for someone to secure a license from ERA in order to start operations. The absence of an appropriate institutional framework for supporting rural electrification programs and the inability to capture the value of positive development externalities in setting of the tariffs has affected investments in rural energy

4. Financial Risks Hydropower projects in Uganda are sound investment projects otherwise they would not be able to attract private foreign investors. But the high capital


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requirements (equity +debt) for hydropower investments and the weak national capital market de facto prevent domestic investors from entering this business area. Unless Uganda develops a policy, an associated strategy, and instruments for facilitating the market entry of domestic bond and equity investors, hydropower investments will be financed by private foreign equity and debt capital. This in turn will mean that the capital surplus from hydropower generation projects will be exported abroad. The national economy benefits from the supply of power; but the impact on national capital accumulation is limited to public revenue raised by the company tax. The inadequacy of financial intermediation mechanism; The local financial sector is generally weak. The banks and other financial intermediaries have no experience with project financing in rural electrification. Previous financing for electrification has been for diesel generators installed by private rural enterprises. The payback period in these investments correspond to the two-three years maturity of the loans. It has been proved that the repayment period in investing in power projects is more than 20 years. The banks that have been approached by the developers are willing to give money up to a period of 8 years. This puts the developer at a risk of not accessing equity fund for development. There is also no rural energy lending experience in Uganda and so project finance is a new project line for the banks. To finance hydro and grid extensions, some projects i.e. those with long payback periods where revenues depend on uncertain demand forecast about the ability of consumers to consume electricity in sufficient quantities and at cost coverage prices are considered high risk lending activities. The interest rates are also still high in the commercial banks, and some of these projects do not look financially attractive to the banks.

5. Technical risks Due to cost-competitive hydropower sites, Uganda has a comparative advantage compared to Kenya, Rwanda and Tanzania in the production of electricity. Uganda develops its power generation capacity in a step-wise manner, putting new plants on stream when new capacity is needed in order to cover the growing national demand for peak capacity. The domestic demand focus results in a surplus of energy generating capability – at least for an initial number of years - when a new hydropower plant comes on stream: • One reason is the lumpiness of new generation investments – the new plants

add 200-250 MW at a time, whereas demand grows at 20-30 MW per year. During the early years of operation, this results in both surplus capacity and surplus energy.

• The other reason is the daily (and annual) load factor (average MW/MW

peak). Hydropower in Uganda is run-of- river with limited, 4-5 hours, storage capacity. Because of limited storage capacity it is inevitable that Uganda


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during normal rainfall years has surplus energy during off-peak periods which can be exported.

So far, capacity expansion planning is done with reference to national capacity needs; the possibility of exports tends to be included as a “by the way, there are some possibilities for exports”- type of exercise. Due to the likely existence of substantial surplus energy, it is imperative that Uganda develops a coherent strategy for the development of its power generating potential, where the least-cost analysis of options for capacity additions is undertaken within a broad framework that combines the satisfaction of domestic demand with negotiated export deals and associated investments in regional transmission grids. This serves the dual purpose of minimizing the domestic cost of supply per kWh (promoting the overall objective of “productivity enhancement”) and of maximizing the foreign exchange earnings from the power sector. Other technical risks include the following: • Renewable Energy Resource Data is not readily available While it is

widely accepted that Uganda is well endowed with exploitable renewable resources including biomass, hydropower, solar and geothermal energy and possibly wind; the detailed resource assessment information required to prepare for a specific project is not readily available, and this poses a bottleneck to the new independent developer who has nowhere to start from. For them, getting such data proves to be an expensive affair.

• Inadequate capacity to promote renewable energy, identify prepare and appraise projects There is a critical lack of adequate local capacity to develop renewable energy projects with significant needs in all areas such as project identification, technical design, project analysis and managerial skills. This has led to sourcing for international consultants who are very expensive and quite out of reach for the local private investor.

In the notice of intended application for a license, an entity with the intention of setting up an electricity project must demonstrate among other things, that it has the necessary technical capacity and experience. The company does this by providing a detailed statement of its technical and industrial competence and experience to undertake the proposed project.

The companies with the experience, mostly foreign ones, such as SN Power, have always presented this information. However, in some of these cases where a company has claimed that they have the requisite experience, it has not always been possible to countercheck that this experience is available at the time when the application should be advertised. This is especially so when the company is foreign owned and the experience foreign –based. Besides, at the notice of intended application stage, it is considered less critical, as this would have to be crosschecked at the license stage.


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Other companies, mostly local ones, do not have the experience, as there has not been much similar project development in Uganda. NB: Most applications actually come from local companies. However they demonstrate in their applications that they would rely on technical and industrial support from external sources. Some of these local companies include Hydromax, Mt Elgon, USEC, etc. While in many cases there exists some written information pointing to links with the claimed external support, the participation of the entities with the claimed links has not always been visible and mostly it has been non-existent. An example is Mt. Elgon Power Co Ltd who has claimed to have support from one company at a certain time only to present another company later, which has also did not materialize.

Unfortunately, the experience and capacity gaps have been identified as seriously delaying the project development studies and tying up sites with not so competent companies for at least the period of the permits. The analysis of the notices of intended application should probably extend to analysis of companies supposedly involved in the application as providers of external support. Additionally, more binding legal agreements between the applicant and the supporting companies or commitment to the project should be provided. It is more worthwhile to prevent time wasted on projects that will not progress anyway.

• Poor Structuring Hindering External Support and Interest Through

dialogue with some of the project developers, it is reported that their partners have not always responded positively at this early stage because they are not certain that the project developer has all the necessary permissions yet. They supposedly want to participate in projects with a high likelihood of support from the government. The key factor to address is the structuring of the projects. Information relating to the project (ownership, conception, etc) in addition to the priority accorded to the project with respect to the needs of the country must be available. No serious investor will be interested in a project, which ranks low. There are so many potential projects but no recent combined ranking of all small potential projects ever studied has been done with respect to the grid-power needs and this tends to create the impression that planning is stochastic. On the side of the local investors, their criteria for choosing a particular project is also not clear. What is clear is that, the local developers do not conduct good desk and pre-feasibility studies to determine the attractiveness of their projects, before marketing them to potential partners or embarking on expensive feasibility studies associated with say, Hydropower Development. This is evident in the general quality of notices of intended application. Some of the developers move to feasibility studies with no idea as to the contents,


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the cost, and a budget, pointing to little pre-feasibility assessment. Some budgets have also been too high for the small hydro studies, as is the case with the first Progress Report from USEC.

The government has in the past conducted some pre-feasibility studies and ranked some of the projects, but usually this was done relative to a set terms of reference with a closed objective. For example, the AERUS study had specific objectives to look for power supply options to districts with a dire energy need so the best ranked projects had a good local out look, but were not necessarily the ones with a better national outlook regarding grid electricity supply. The SWECO study of 1999 had a view of grid-connected projects but it was limited to 9 sites and the method of selection of these sites was not clear.

6. Other Factors • Consumer Ignorance

Although not served, the rural population has been exposed to the idea that the provision of infrastructure including electricity was the responsibility of the government. Political promises of rural electrification may not have been fulfilled yet the memory of such promise is still vivid. Shifting initiatives to local private investors requires more adjustment in thinking. This calls for intensive consumer awareness.

• Economic Issues

The upfront investment in grid and hydropower project is huge. This results in long payback periods for investment. Initial demand, when loans have to be repaid is relatively low, compared to urban areas electrification. The cost of investment per volume of KHW sales is much higher, whereas ability to pay high tariffs on average is lower and subjected to seasonal fluctuations caused by heresy patterns. Investors would not have sufficient equity, if the projects were to be fully commercially financed with a lender imposed requirement of say 25% of investor equity. Even if sufficient equity were available to principle, the risk-adjusted rate of return on equity required to attract investors would put the cost of electricity outside the range of most rural people.

• The market for power It has been noted that Uganda has the lowest per capita electricity consumption (44 KWH/year) in the region. Uganda is also among the poorest in the world i.e. per capita of US $ 300. This kind of population consists of those residing in rural areas and their capacity to use electricity, which is limited, thus limiting the demand side of the system and consequently affecting the market for electricity. Interlinked with the market is that, the energy maximum demand in Uganda is at peak hours (6.00pm – 11.00pm) in


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the evening. After that, the power produced from the sources will be idle because no one works from 11.00pm to 6.00am in the morning.

• High costs of extending power to rural areas

Hydro and grid based electricity is an investment in infrastructure with high upfront costs. Extending the transmission grid to one locality facilitates the subsequent extension of the transmission grid to the next locality. The initial cost per customer connected in a distribution grid is high. The marginal cost of subsequent intensification of adding more customers to the grid is lower, yet the reverse from the initial customers from the start covers full cost of operation and maintenances, repayments on loans and at least some returns on equity. This results into high tariffs, which scares away the would-be consumers, eventually becoming a barrier to investments.

• Political regulatory risks

Guarantees against regulatory risks should not be entertained, as they may discriminate among the various investors in the same sector.

• Environmental costs The production of electricity often has significant environmental costs. The exclusion of environmental costs makes electricity cheaper than it would have been otherwise. Thus, demand for electricity is higher than it would have been if these costs were accounted for in the price. The environmental damage from this incremental amount of electricity consumption is attributable to the subsidy that arises from the exclusion of environmental costs.

deliverable 3.1 initial assessment of risks and barriers ... · 3.3 tariff reforms ... this table...

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